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Noble Energy (NYSE:NBL)

Q1 2012 Earnings Call

April 26, 2012 10:00 am ET

Executives

David R. Larson - Vice President of Investor Relations

Charles D. Davidson - Chairman, Chief Executive Officer and Member of Environment, Health & Safety Committee

David L. Stover - President and Chief Operating Officer

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

David W. Kistler - Simmons & Company International, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

John Malone - Global Hunter Securities, LLC, Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Operator

Good morning, and welcome to the Noble Energy's First Quarter 2012 Earnings Call. I would like to turn the conference over to Mr. David Larson. Please go ahead, sir.

David R. Larson

Thanks, Ryan. good morning, everyone. Welcome to Noble Energy's first quarter 2012 earnings call and webcast. On the call today, we have Chuck Davidson, Chairman and CEO; Dave Stover, President and COO; and Ken Fisher, CFO.

This morning, we have issued our earnings release for the first quarter, and it is available on our website. Later today, we expect to be filing our 10-Q with the SEC, and it will also be available on the website.

The agenda for today will begin with Chuck discussing the quarter and highlights of our exploration inventory and the progress that we're making on our Eastern Mediterranean projects. Dave will then give a detailed overview of our operational programs and near-term plans.

[Operator Instructions]

Should you have any questions that we don't get to this morning on the call, please don't hesitate to contact us and we'll do the best we can to answer you. I want to remind everyone that this webcast and conference call does contain projections and forward-looking statements based on our current views and most reasonable expectations. We provide no assurance on these statements, as a number of factors and uncertainties could cause actual results in the future periods to differ materially from what we discuss here today. You should read our full disclosures on forward-looking statements in our latest news release and SEC filings for a discussion of the risk factors that influence our business.

We'll reference certain non-GAAP financial measures here today such as adjusted net income or discretionary cash flow. When we refer to these items, it is because we believe they're good metrics to use in evaluating the company's performance. Be sure to see the reconciliations of these items in our earnings release tables.

With that, let me turn the call over to Chuck.

Charles D. Davidson

Thanks, David, and good morning, everyone. I'm going to start out by reviewing our first quarter results, including a number of significant accomplishments, and then I will move on to discuss some of our forward plans for the remainder of the year.

As you can see from our press release that was issued this morning, this was another strong quarter for Noble Energy. And also, if you've seen our recently-published annual report for 2011, I think you would agree that this quarter's results fits well with our annual reports theme. That theme focuses on the single word, now. In other words, it's all about what we are delivering now. For several years, we've talked about transitioning, transforming and preparing for growth. However, as our report highlights, that preparation work is behind us, and now we are seeing the results. We are now experiencing real growth that is expected to last for many years into the future. And so the future has become now.

Starting with the financials. The adjusted net income for the quarter was $314 million or $1.75 per share diluted, that's an increase of 31% compared to the first quarter of last year. Our only adjustment was for unrealized commodity derivative losses due to strong oil prices.

GAAP net income was $263 million or $1.47 per share diluted. Quarterly revenues were almost $1.2 billion, a 30% increase over the first quarter of last year. Crude oil and liquids represented nearly half of our sales volumes and combined with strong prices accounted for over 80% of our revenue for the first quarter.

Our sales volumes were a record 243,000 barrels of oil equivalent per day, up 10,000 barrels of oil equivalent from the fourth quarter of last year and up 13% from the first quarter of 2011. Our sales exceeded quarterly guidance range that we issued earlier this year, and essentially all of the increased production was from crude oil and liquids sales.

The outperformance was driven by exceptional operating performance at Aseng, which completed its first quarter production, as well as continued growth from the horizontal program in the DJ Basin and the deferral of some maintenance downtime in our non-operated Alba facilities from the first to the second quarter. The good news is that, that Alba maintenance has now been completed, and the field is back up.

47% of the total sales volumes for the quarter were liquids. That's up from 40% in the fourth quarter of last year. Our U.S. sales volumes were 131,000 barrels of oil equivalent per day with 45% being liquids. Compared to the first quarter last year, U.S. sales volumes increased 15%, largely driven by increases from Wattenberg and the addition of the Marcellus Joint Venture.

The DJ Basin production totaled 73,000 barrels of oil equivalent per day, with oil representing 39% of the volume mix, and Natural Gas Liquids representing 17% of the total volumes.

DJ Basin production from the horizontal program averaged 18,000 barrels of oil equivalent net in the first quarter of this year, greater than a fourfold increase over the 4,000 barrels of oil equivalent per day production in the first quarter of 2011.

The international region contributed sales volumes of 112,000 barrels of oil equivalent per day. That's an 11% increase over the first quarter last year. Strong operational performance, coupled with exceptional reliability, resulted in Aseng crude oil sales averaging 18,000 barrels per day net for the first quarter. International production was 5,000 barrels of oil equivalent below sales with the additional sales volumes attributed to the timing of crude and condensate listings in Equatorial Guinea.

Price realizations for crude oil and condensate were $110.80 per barrel. That's up 14% from the first quarter of last year, while domestic natural gas realizations were down 36% to $2.62 per 1,000 cubic feet. Israel gas price realizations were near the midpoint of our guidance range and they averaged $4.51 per 1,000 cubic feet for the quarter.

Total production costs, which included lease operating expense, production, ad valorem taxes, transportation and gathering expenses were $8.09 per barrel of oil equivalent, which is below our expected average for 2012. The liquids projects have contributed to increases in DD&A. Rates, which at $14.11 per barrel oil equivalent, are still below our annual guidance range.

The unit costs are expected to fluctuate as the production mix changes throughout the year, but we still expect to finish the year with unit costs within our annual guidance ranges. In general, growth in liquids production will bring higher unit cost, but also much higher revenues. In today's world where oil and gas prices are significantly disconnected, we believe the only way to rationally evaluate producer cost is on a cost-per-dollar of revenue basis.

When we look at Noble's cost from this perspective, we actually see a very positive trend. Discretionary cash flow for the quarter was a record $716 million, that's up 24% from the first quarter last year. As expected, discretionary cash flow was growing faster than production due to rapidly increasing liquid content of our production stream.

Our financial position remains strong with over $1.1 billion in cash on the balance sheet and total liquidity of $4.1 billion. In addition to the solid financial results, we experienced a number of operational achievements. We assumed operatorship in a liquids-rich area of the Marcellus Joint Venture. We made another discovery offshore Israel, at Tanin, with an estimated gross resource -- mean resource of greater than 1 Tcf. And we've contracted approximately 4.1 Tcf of new natural gas sales from Tamar in Israel or approximately 45% of the fields estimated being resources. These new contracts are expected to generate $28 billion in gross revenues over approximately the next 15-plus years.

As you can see, the first quarter was a great start to 2012. We're bringing on high-value production and actively progressing major projects that will fuel our growth over the next few years. We also continue to invest in exploration, whose value has already been demonstrated by our significant discoveries in West Africa and the Eastern Med, as well as the Gulf of Mexico.

In West Africa, we're continuing a multi-year exploration program which has already discovered 350 million barrels of oil equivalent net. We believe this area has significant running room with currently identified inventory of high-quality prospects, representing around 900 million barrels of oil equivalent net unrisked resources. We plan to drill the prospect in Cameroon before the year ends, which has an estimated gross unrisked resource range of 75 million to 230 million barrels of oil equivalent and a 38% probability of geologic success.

Exploration teams are also active in the Deepwater Gulf of Mexico where we plan to drill 2 exploration wells this year in addition to the ongoing appraisal at Gunflint. The primary exploration well candidates include Deep Blue, Troubadour and Big Ben. In combination, Troubadour and Big Ben have a gross mean resource estimate of over 90 million barrels of oil equivalent. They're oil plays in close proximity to each other with similar characteristics to Galapagos and which could be brought to production quickly, if successful.

But exploration is not just an onshore activity as evidenced by the prospective play in the Western U.S. that we announced last month. We've been building this position in a new resource play, and we're noting today that it's in Nevada, and we now have over 330,000 net acres in the play. The play is different than what's been historically pursued by industry in Nevada. The target section is similar in age and depositional history to productive petroleum systems in the Uintah Basin in Utah, they have produced hundreds of millions of barrels of oil.

We're currently planning 3 seismic surveys and expect to begin pilot well tests next year. At present, we estimate net risk mean resources in the 500 million barrel of oil equivalent range, which fits nicely in our global exploration portfolio.

Dave, excuse me, Dave will cover in detail our results in the Niobrara. I just wanted to highlight here that we've expanded our acreage position in Northern Colorado outside Wattenberg to around 230,000 net acres. We've integrated our geoscience work with our drilling and completions expertise to unlock and expand additional opportunities outside Wattenberg. We continue to apply our learnings to increase well performance, both within and outside Wattenberg. By the end of this year, we estimate that about 40% of our production from the DJ Basin will be from horizontal wells.

I want to spend a few minutes on our activities in the Eastern Mediterranean. The Khmer project is on schedule for sales at the beginning of the second quarter next year. As I previously mentioned, nearly half of that resource is now under long-term contracts. A pre-FEED study for floating LNG is nearly complete and may transition to a FEED study later this year.

Domestic Israel gas demand continues to grow, and we're evaluating options to timely meet that demand. With respect to Leviathan, we're continuing our partnering efforts. Our preferred partners expected to bring value through significant LNG plan expertise, financial strength and global gas marketing expertise. We've had a number of informal discussions with interested parties and we'll be launching a formal selection process in conjunction with our partner shortly.

We are encouraged that there is a broadening support for exports from Israel. Our belief that exports will contribute significantly to the energy security and economic growth for the state of Israel. Earlier this month, the gas commission studying Israel gas exports released its interim recommendations. These recommendations will be evaluated and commented on before the commission makes its final recommendations, which are expected in June. The final recommendations will need to support the continued exploration and development of the Levant Basin and ensure the economic viability of development projects to maximize energy security and value for Israel. It's our intention to work closely with our partners, including the State of Israel to contribute to the process we're able to do so.

So with that, I'm going to turn the call over to Dave who'll give you an operational update and provide more details on our ongoing work.

David L. Stover

Thanks, Chuck. I will begin my update in the DJ Basin, the core area where we are continuing to generate impressive results from our horizontal program.

In the first quarter, our net DJ Basin volumes averaged a record 73,000 barrels of oil equivalent per day, that's 25% of the total production or 18,000 barrels of oil equivalent per day from the horizontal program. Crude oil contributed 28,800 barrels per day, and Natural Gas Liquids added 12,500 barrels per day, representing a 56% liquid content from the DJ Basin.

The high liquid content has continued to provide significant economic value and we're focused on projects that further increase our liquids production percentage. Expect the contribution from the horizontal drilling program to continue to grow rapidly as we transition from vertical to horizontal drilling in the Wattenberg field.

Our current April production from the horizontal program is 21,000 barrels of oil equivalent per day net with a 68% liquids content. We estimate the exit rate for 2012 from the horizontal program to be 32,000 barrels oil equivalent per day net, which is very similar to our total Wattenberg volume when the Patina transaction occurred in 2005.

We recently added our seventh operated horizontal rig alongside the 4 vertical rigs that we currently operate. Additionally, we plan to add 2 new fit-for-purpose horizontal rigs in the fourth quarter, which will bring us just 9 horizontal rigs while we reduced to 2 vertical rigs by year end. This rig activity will enable us to drill over 170 horizontal wells in addition to over 200 vertical wells this year.

Through our water management strategy, we have secured over 100% of the water required to execute our 2012 completion program. We're also working on future infrastructure needs beyond 2012 that includes water wells, storage ponds and infield transport lines, which will reduce truck traffic and lower transportation and procurement costs.

We estimate that these benefits, in addition to the efficiency gains of pad drilling and shared service facilities, will minimize our footprint and eliminate 56 million truck miles and reduce NOx emissions by 1,300 tons over the next 5 years. An example of our more-efficient operation is our EcoNode facility where we've recently finished the completions of our 9-well pilot test. All 9 wells are now on production.

As a reminder, we're evaluating several things with this pilot program. First, we're testing recovery from 80-acre and 40-acre spacing. We're also evaluating vertical recovery within the 300-foot Niobrara with a C chock lateral. We have a month of production history now on over half of the wells in the pilot, and we are encouraged that their average 30-day per well rate is around 500 barrels of oil equivalent per day with a liquid content over 80%. After obtaining several months of production history, we will have additional results to share later this year.

Since our last earnings call, we've completed our first horizontal well specifically targeting the Codell interval. It was drilled in the high geo, our portion of the Wattenberg field in a section where 31 vertical Codell Niobrara wells have been producing. Although it is early, initial results have been promising. We are moving ahead with plans to drill 6 to 8 similar wells this year.

We haven't fully discussed our Niobrara C bench evaluation program before, but we have now completed 12 wells in this interval across portions of the field. The results have been very good with 30-day per well rates ranging from 300 to 600 barrels oil equivalent per day. These tests are designed to understand the Niobrara vertical communication between the B and C benches and how we designed a program to maximize recovery from this 300 to 350-foot hydrocarbon saturated reservoir.

Another value-optimization opportunity is extended reach laterals. We just finished drilling our second extended reach lateral, which reached TD in the lateral length just under 9,000 feet in 8.5 days, beating the performance of our first extended reach lateral by 15%. We're currently drilling our third and plan to drill a total of 12 to 15 extended reach laterals this year.

In Northern Colorado where our acreage is northeast and adjacent to the Wattenberg field, we've expanded our position to 230,000 net acres with the addition of 48,000 net acres over the last few months. Results from 5 recent wells are extremely encouraging, with an average 30-day per well rate of 600 barrels oil equivalent per day and with our highest average crude oil content of approximately 80%. We now expect to drill about 20% of this year's DJ Basin horizontal program, or over 35 horizontal wells in this area, with the objective of moving that into full-development mode by year end.

To summarize our efforts in the DJ Basin, we have a very robust horizontal drilling program for 2012. The majority of the wells will be in the more oil-prone areas of Wattenberg in Northern Colorado. We'll continue to evaluate well density in the horizontal potential for multiple pay intervals.

Finally, to illustrate the impact of our horizontal program, by year end, we expect 40% of our DJ Basin production will come from about 4% of our producing wells. This clearly demonstrates the substantial production and technology improvements that have been implemented over the last couple of years.

I'll now shift my comments to our Marcellus horizontal program. In the dry gas areas, our current plan is to drill less than 60 dry gas wells this year, while we continue to visit with our partner about the optimum dry gas activity level throughout the year. The drilling is focused in Southwest Pennsylvania, where we have a very high net revenue interest averaging 96% and expected recoveries over 6 Bcf per well.

In the wet gas area, we're maintaining our program and expect to drill nearly 40 wells this year. You will recall that in January, we started operating our first rig in the wet gas portion of the acreage. With the addition of 2 more rigs in the second half of 2012, we plan to be operating 3 rigs in the wet gas area by the end of the year.

We're presently conducting completion operations in Marshall County, West Virginia on a 5-well pad, and we'll then begin completion operations on our second pad containing 8 wells. We anticipate our first operated production at the end of the second quarter.

Our overall Marcellus strategy focuses on an efficient repeatable process that builds on continuous improvement, such as we have experienced in the Niobrara. We believe that we can improve our recoveries by integrating geology and completion technology for optimum well placement and stimulation design. In addition, we expect cost reductions to improve drilling efficiency and fit-for-purpose rigs.

Shifting to the Deepwater Gulf of Mexico, where we recently brought our South Raton project online, that is now producing just over 3,000 barrels of oil per day net with some associated gas. At our Galapagos project, all topsides and subsea work is essentially complete. The final commissioning and hand over to operation's ongoing. We still expect to be on full production by the end of the second quarter.

Drilling operations continue to progress at Gunflint with results expected in the second quarter, which has helped us to better define our current resource range of 70 million to more than 500 million barrels oil equivalent gross. After logging and evaluation, we will make a decision whether to sidetrack the well to further define the resource range. We also expect to drill a couple more exploration wells this year, as Chuck previously mentioned.

Moving to the Eastern Mediterranean. We had several positive developments. In Israel, we had a significant discovery at Tanin, which expanded our resource base with our sixth consecutive Eastern Med discovery. We also announced the execution of a Gas Sales Agreement with Israel Electric Corporation. Contract includes an option in which they can increase the sales volume from 2.7 Tcf to 3.5 Tcf. If they exercise that option, overall total contracted gross sales will be 4.9 Tcf or a little over half of the main resource estimate for Tamar.

The estimated value of the 4.9 Tcf is around $33 billion gross. The Tamar project is progressing on schedule for commissioning to begin late this year and sales to start early in the second quarter of 2013. Development drilling has been completed and final well completions should conclude early first quarter 2013. Jacket and deck fabrications are over 80% complete, we expect final installation in the fourth quarter.

Subsea pipeline installation is also complete, and expansion of the Ashdod onshore receiving terminal is underway. Supported by contracted volumes, we expect gross Tamar sales could average around 700 million cubic feet per day by mid-2013. In-country demand continues to grow, and we're already evaluating other options to deliver incremental gas. The Tamar pre-FEED floating LNG study is ongoing, and we expect a decision on moving to a full FEED study to occur in the third quarter.

As we continue to make progress on Tamar, we're closely managing our production for Mari-B in order to conserve deliverability. We have just completed the Noa #2 well and the Pinnacles well and expect to complete the Noa #3 well in mid-May. Initial indications from Noa and Pinnacles are encouraging, and it's our expectation that these 2 fields will provide deliveries in excess of 150 million cubic feet per day beginning this summer.

In addition, operations are ongoing to test the deep oil concept at Leviathan #1. We still expect results in the second quarter before returning uphole for a flow test of the main Leviathan gas interval in this wellbore.

Moving now to our activity in West Africa. I'll begin with Aseng. We initially brought Aseng on production at 50,000 barrels per day gross, and have increased production to 60,000 barrels per day with greater than 99% uptime. Our cumulative production reached 8 million barrels at the end of the first quarter, which is impressive when you consider that Aseng was initially scheduled to be online in July of this year.

Turning to our non-operated Alba production. Our previously planned maintenance turnaround was shifted, which resulted in increase production in the first quarter but will result in reduced production from Alba in the second quarter. The planned turnaround is now complete, and the field has been returned to full production.

Looking ahead, our Alen-operated project remains on schedule for first production in the fourth quarter of 2013. The platform fabrication is over 50% complete, subsea umbilicals and controls are nearing completion. We're currently completing the final production well and flowline installations are scheduled to begin in June.

Concerning our discoveries at Carla and Diega, we have assembled project teams to evaluate development tieback options. We have also contracted with an engineering firm to assist in preparing for concept selection. With regard to the exploration program in West Africa that Chuck mentioned, we're actively evaluating rig options for this multiyear program. Based on water depths, we anticipate this will be a mix of jack up and floater activity.

Before wrapping up, I want to update the status of our U.S. onshore divestment marketing effort. Over the next month, we'll be opening separate virtual data rooms for Texas and Oklahoma Panhandle properties, Kansas oil assets and a Permian oil package and plan to market additional properties in the coming months.

Now let me review our volume guidance for the second quarter and the year. Full year guidance remains unchanged at 244,000 to 256,000 barrels of oil equivalent per day. We expect second quarter sales volumes to range between 224,000 and 232,000 barrels of oil equivalent per day.

Compared to the first quarter, 85% of the change is attributed to international gas. Second quarter volumes will be impacted by the Alba maintenance shifting from the first to the second quarter, lower production levels at Mari-B and third-party processing downtime in the DJ Basin. Volumes will recover quickly in the second half of the year from full production in West Africa, new production in Israel, start up of Galapagos and the Gulf of Mexico and the growing onshore programs. As a result, second half volumes are expected to be more than 10% greater than volumes in the first half of the year.

In summary, we're excited about the activity in each of our core areas. We're driving liquids growth in the DJ Basin, Gulf of Mexico and West Africa. Also in the DJ Basin, we continue to unlock material, additional resources. Significant exploration is ongoing or planned this year in the Gulf of Mexico, West Africa and Eastern Mediterranean, and we're moving forward to realize the tremendous value of our Eastern Mediterranean assets while preparing to bring on substantial new production next year in Israel and Equatorial Guinea.

With that, Ryan, we will open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions]

And we'll take our first question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Following up on your comment with regards to the Niobrara C bench where you completed those 12 wells. Can you talk to what that means or what you think that means, at this point, for how many with a combination of vertical and horizontal wells you can drill per section and over what level of area extent within the Niobrara or within Wattenberg you feel you like that confidence?

David L. Stover

Yes, I think, Brian, it's still early in the evaluation. I'd say what we've seen has been very encouraging, which would lead me to believe we'll have a mix of C and B bench laterals over time. I'd say and that'll differ probably in different parts of the field as you'll see different performance contribution from the C and different areas of the field. So I'd say it's still probably too early to say that we'll have overlying and underlying C and B bench everywhere. It may be staggered in some places, but I think we'll know a lot more about that by the end of the year. What I'll say, though, is that from what we've seen so far, the productivity of the C bench in a number of the areas has look just as good as the productivity of the B bench, which leads us to that conclusion that we will have a combination of both various portions of the field as we move forward. So we'll continue to learn more about that. What it means is continuing to unlock opportunity in resource for us.

Charles D. Davidson

I would just add, Brian, that we continue to test the horizontal in areas, as Dave's noted, areas that have been previously developed vertically. And in the case of the EcoNode facility, we had 17 vertical wells already drilled in that section in which we put the 9 horizontals across it, which included both, not only wells in the B, but also a well in the C bench there. So we're really testing it under real conditions and we just need more time and more data to really evaluate how we can expand it and how we would expand it across the field.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And my follow-up is regards to the Nevada play. You compared it to the Uinta Basin in terms of age and geologically. Can you talk about your expectations for oil quality would be, and then also what you're -- I guess beyond the plan C, you talked about the pilot wells in 2013 why you think that this was an area of focus for industry previously.

David L. Stover

Well, it's -- and again, some of the Uinta production has high pour point oil and we would expect the same thing out of this prospect. It's tertiary, and that's why we refer to the production that was out of the Uinta basin. That is as we have looked at industry, that it's not been a focus point for industry in Nevada before in this particular section. We carry the play into it based on a lot of regional work that we had done. So that was how we came to that conclusion. So as you know, we've been gathering this acreage position. We've gotten to the point where we were more comfortable about talking about it after securing the acreage, and of course, we've got to do some work as we go forward. But that's our current thinking on it. We'll know more with some pilot wells and as we do further evaluation work continuing into next year.

Operator

And we'll take our next question with Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Following up on the Nevada question there. If the crude's kind of high paraffin, well, actually crude, what does the refining capacity look like for you guys or have you started that evaluation process to understand ultimate deliverability of the options?

David L. Stover

I would just say that we have started working on what the infrastructure needs would be. As you would guess, there's not a lot of infrastructure since this is a new concept play. It would likely be rail, be likely heated railcars, which is what some of the other production up in that part of the world would utilize. But it's pretty early, pretty early in the process other than we have anticipated, there will be some additional infrastructure needs to develop this.

David W. Kistler - Simmons & Company International, Research Division

Okay. And following up on that and maybe combining it with the continued success in the Niobrara, how does that change maybe the capital outlook for 2013? Could we see that biased higher versus the 5-year plan you gave us at the Analyst Day? And maybe any comments you can make towards what that would do to your liquids mix, going forward, would be helpful.

David L. Stover

Well, I guess I would just say that we constantly look at the mix of our capital, and what's happening this year, of course, is that we've pushed capital out of some of the dry gas that we'd anticipated in the Marcellus and we pushed it into the Niobrara. And given where the market environment is today and given the great results that we're getting in the Niobrara, we'll continue to do that in 2013. But it's too early to say what impact that might be on the overall capital program, because we're constantly moving things around. So it's -- how it works in our company is the best projects get to the table first and get the first capital, and the Niobrara is doing extremely well. And so we're trying to do everything we can to accelerate and grow that program as fast as reasonably possible.

Operator

And we'll take our next question from Arun Jayaram with Credit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Arun Jayaram, Credit Suisse. Chuck, I was wondering if you could walk through some of the development options that you're thinking about today for Leviathan and Aphrodite? And perhaps discuss some of the pros and cons from a timing and cost perspective of development options, including Cyprus, Northern Israel or the Red Sea.

Charles D. Davidson

Well, I think when you look at Leviathan and also keep in mind that we're getting new information as the committee in Israel study exports, there is a view that the larger fields will be developed as a combination of both the domestic market and export. So I think in Leviathan, while we'll want to basically have a good plan for both going forward is that we could easily see domestic production from Leviathan before we see exports, and that is our current thinking right now is that it will be a 2-step process. Just by the way, as we noted that we're evaluating potential exports from Tamar with a floating LNG. So certainly for the large discoveries, you would see a mix of domestic production, which would likely come sooner combined with exports. Cyprus, the market there, there is a need for gas domestically, but it's of a smaller scale. And so we certainly see that the Cyprus will go towards mainly an export market, and those markets we see right now could be either European or Asian. And really one of the -- why this whole partner selection process that we discussed and touched upon is so important, is that can bring us not only a partner with the expertise in LNG and global gas marketing, but conceptually, it could also bring a partner that actually has a market. So we need to go a little further on that. But we've been working through this pre-FEED work on a number of sites that cover everything from Jordan to Israel to floating to Cyprus and have looked at the viability in a number of those. And so we're keeping many options in play at this point, but I think probably the only thinking or perhaps new information is that we see that probably all the major fields will have a domestic component including Leviathan.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And the timing, Chuck, if you did go to a domestic option first before export at Leviathan, what would the timing be?

Charles D. Davidson

I think you're looking at something in that kind of 2016 type time range for a Leviathan. The other thing that you have to consider or enter into consideration, also as you pride in that time frame, you're also looking at additional phase in Tamar also. So you've got probably 2 additional, at least in-country, projects to look at over the next 3 to 4 years.

Operator

And we'll take our next question from Brian Lively with Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

On the Nevada play. Can you just guys just talk broadly where is that within the state? And then I know some of us remember the Chainman Shale that's been tried over the last 2 years. So maybe just some contrast on how this play's different.

Charles D. Davidson

Well, it's in Northeast Nevada. And again, it's a tertiary play. When you look at this section, generally, it's younger than what the industry has chased in Nevada over the number of the decades. We've done a lot of geochem work. The scorecard on this looks pretty attractive, especially when you look at total organic carbon content, some other rock parameters. The uncertainty, of course, you've got the variability of rock types and things like that. But as we mentioned before, we've got this one risked at about over 500 million barrels of oil equivalent. So it has the scale potential. We built a very solid acreage position around it at very low cost, which is the key of being an early entrant, identifying a play earlier. So it fits very nicely in the portfolio. So we're excited about it. I'll tell you that certainly several of us kept asking the team over and over again, how did this one get missed. And so you're asking the right questions because we've been asking him as well. But it was clearly a nice job of people backing up and doing regional work and understanding how they can pull what works in another part of the country or what we do on our international program, we sometimes look completely around the world.

David L. Stover

And something we apply new technology to that really unlocks some of this resource.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Sure, interesting. And my second question is just probably on NGLs. And if I recall them, your Niobrara NGLs go through Con-way. But if you guys could give just some updates on what you're seeing on the NGL realization front, have you seen any stabilization in the NGL pricing that's been coming down recently?

David L. Stover

You're right. Right now, the majority of our DJ Basin NGLs go through Con-way. I'd say probably in another 1.5 years, 2 years that'll flip with the new line that's going in that'll take a lot more of that portion to Mount Bellevue. But what we've seen is kind of recently we're at -- when you look at the NGL mix, you're at about a little over 40% of West Texas Intermediate pricing, and that's come down some from probably -- late last year, it was closer to 50%. So again, I think we mentioned that last time we had the call, our ethane contribution's just right around 30%, 30%, 31%.

Charles D. Davidson

I would also add and Dave referenced that the recent market is hard to read because there was a fractionator that was down there that really backed things up. So that put another wrinkle in the market, but that work is being completed. And it was noted, that was one of the things that affected our guidance for the second quarter.

Operator

And we'll take our next question from John Malone with Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just to get a little more granular, can you guys sort of walk us through the balance in Israel with Mari-B declining? And I then think you said 150,000 -- I'm sorry, 150 million cubic feet a day on the summer from Noa to Pinnacle. So can you just kind of walk us through how production goes towards Tamar next year?

Charles D. Davidson

Yes, we've been holding Mari-B or we've ramped down Mari-B to this quarter probably around in the 150 million to 160 million cubic feet per day range. In the third quarter, we expect, as I mentioned, Noa and Pinnacles to come back on. So in total, we should probably be a little north of 300 million a day in the third quarter as we get into the summer. And then we're just going to have to see how some of the new wells that like Noa and Pinnacles hold up as we start to produce those. They're not as large a reservoirs, but we'll see how well they hold up going into the fourth quarter, which will get us real close to when Tamar starts to come online. And we'll be starting the commissioning of Tamar in the first quarter and have that ready in early second quarter. And as we've mentioned, we expect the volumes from Tamar then as we get that lined out next year. By mid-next year, it will be back up to probably close to 700 million cubic feet per day from Tamar.

Operator

And we'll take our next question from Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

If I may ask 2 questions. One is Nevada. In this case, you're going to train your staff out, are you going westbound? Question number 2 has to do with the Wyoming Niobrara play. Are you guys -- how's your feeling towards this particular portion of the play? And then in terms of extended lateral in the main part of the Wattenberg Field, would you end up doing a whole lot of that stuff rather than your more conventional laterals?

Charles D. Davidson

And Irene, I just want to make sure I understood your first question on Nevada. Was it on the transportation, our anticipation of what direction it would go?

Irene O. Haas - Wunderlich Securities Inc., Research Division

Yes, yes. You go -- is there any chance you can go to California?

Charles D. Davidson

I will tell you it's way, way early in the stage now to decide on where that would go. Again, we mentioned, I think, in response to an earlier question that we expect this to be high pour point oil. So we want to look very carefully at what refineries can best utilize that as you go forward. But, I mean, we've got a lot of exploration work to do before we get to that point. On Wyoming, right now, we've been working on our way north. And so we're, as Dave noted, we've expanded into Northern Colorado outside the Wattenberg Field. We've got some limited work in Wyoming, but it's nowhere near at the maturity level that we've gotten in Colorado. So right now, the bulk on -- Dave can add exactly how much, but I'd say a vast majority of our investment in Niobrara will be in Wattenberg and Northern Colorado in the extended area.

David L. Stover

Yes, I think the Wyoming work, Irene, will be just a few focused wells to continue to try and understand better these different pods, as we call them, that we'd breaking it up into different areas and portions of the acreage out there that we'll continue to evaluate. But Chuck's right. I mean, the activity right now is focused on accelerating the Wattenberg program, defining the Northern Colorado program and moving that forward to get it to the same place we are in Wattenberg. As I've mentioned, we expect to be there by the end of this year moving into next year. I'd say on the longer laterals, the extended laterals, if we can get the type of performance we saw from the first well and it's the only one we really have on production at this point, we'll be gung ho to move more of that program that way. I mean, there are limitations, especially when you get in areas of the field that have been densely drilled vertically already. So it has probably more application to the north and the east, and then up in to Northern Colorado, which coincidentally, maybe not coincidentally, happens to be our high oil content. So that could play out well, but as I said, we're going to drill 10 to 12 of those this year. We'll get some -- a wider data points or more data points on that type of performance, and then we'll adjust from there.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Which is bench C and Codell as well?

David L. Stover

Same type of thing. I'd say the one thing when you look at the things we're testing in Wattenberg and I'd say now even in Northern Colorado, whether it's on aerial recovery or vertical recovery, the one thing you can say is we have not been disappointed by any of the things we've tested there whether it's C bench, Codell or lateral -- extended laterals.

Operator

[Operator Instructions] And we'll take our next question from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

I wanted to ask about the Gulf of Mexico. The Gunflint well, you guys have been underway with that for a while. Can you talk about where you are right now with respect to the target in TD and what you -- how you make your decision based on what you learn with this first penetration?

David L. Stover

Yes. I mean, we're still drilling ahead. And as we've said, we expect to finish that well in the second quarter. We won't really give out an update as we go along, but we'll wait till we finish the well. If you go back to the first well, that took over 5 months to fully drill, and now we're in an environment where you're doing more testing and more continuous testing post-Macondo of equipment. And so, of course, that'll take a little longer than the first one. But I think that when we get the well down and we log and evaluate, then what we'll be looking at is from what we're seeing and where we are relative to water contacts and where we expect water contacts to be from what we understand. Does it make sense to do a sidetrack to further define the potential, especially with the narrow down that resource range based on what we've seen from the initial logs.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. So...

David L. Stover

That'll be our decision once we get this well down.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. So to clarify that, then you're problem at getting it done in Q1 is really the first, this wellbore, not any follow-up appraisal or anything?

David L. Stover

Right. We're talking about by the end of the second quarter to have the initial wellbore down, and then we'll make the decision on a sidetrack.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. And so maybe if you see water levels, you're more likely to sidetrack updip to try and find it...

Charles D. Davidson

It all depends on -- there is multiple sand here, and so we would expect to see contacts in some. The key is, is we are off on the plank, we're trying to evaluate a syncline feature. And so based on what we see, it could tell us whether oil has build into a second 3-way trap that's off to the side of the main feature. And so we could be sidetracked in either downdip or updip based on what we find.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. And then if I could just lob on a follow-up on that. Galapagos, can you tell -- can you kind of give the detail where you expect to be kind of end of this week or end of this month as far as your operations?

David L. Stover

I mean, what we've said is we expect that to be coming online over the next month or so and be up to full production by the end of the quarter. And by full production, by end of quarter, by the end of June, we should be up to where we're seeing about 10,000 barrels per day of oil net to us.

Operator

And we have no further questions in the queue at this time.

David R. Larson

Great. Thanks, Ryan. I want to thank everyone today for their interest in Noble Energy, and I hope everybody has a nice day. Thank you.

Operator

That does conclude today's conference. Thank you for your participation.

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